Good morning, ladies and gentlemen, and welcome to the Jadestone Energy Full Year 2022 Preliminary Results Conference Call. At this time, all lines are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. I would now like to turn the conference over to Mr. Paul Blakeley, CEO. Please go ahead, sir. Great. Thanks, Laura. Ladies and gentlemen, good morning, and welcome to Jadestone Energy's Full Year 2022 Preliminary Results Conference Call. I'm Paul Blakeley, CEO, and I'm joined in London today by our CFO, Bert-Jaap Dijkstra, and by Phil Corbett, Investor Relations Manager. In this call, we'll run through a presentation which was recently uploaded on our website at www.jadestone-energy.com. It's in the investor relations section, or you can view it via the link on the webcast. After that, let's open the call for question and answer. As many of you are aware, we're reporting our full year 2022 results later than normal. This is a departure which we'll return to next year in April. Slide two. This outlines our standard disclaimers and, in particular, the cautionary remarks regarding forward-looking statements and non-IFRS measures used in the presentation. With that, let's get started, turning to slide three, which picks up on some recent performance highlights from the business during the year and provides a useful snapshot of where we are. You know, upfront, I can only describe 2022 as the most extraordinarily frustrating year operationally. One which largely overshadowed the underlying progress made in a number of other key strategic areas. The first half of the year validated how well our strategy works as we continued to generate significant operating cash flow, building our cash balance to a record $162 million by mid-year, and which arguably could have reached $250 million by year-end if it weren't for the events at Montara. The second half, however, was a different story, highlighting the current over-reliance on Montara for operational and financial performance, showing vulnerability to single events on the asset as we continue to restore the facility to appropriate condition. Since then, we focused on a work program to bring Montara back on stream safely, and having strengthened our procedures to do so with confidence of higher reliability and uptime performance. Almost hidden behind this event, significant progress has been made on a number of fronts. Akatara, for example, is a highlight of 2022, as we sanctioned a project which will deliver low-cost energy to communities that need it. A project which is running on schedule and budget and which will contribute significantly in 2024 and beyond. Akatara is also an important step in our strategic aim to diversify the portfolio, remove our reliance on Montara, and with the inclusion of acquisitions at CWLH and Sinphuhorm, both with potential for building additional equity interests, we're already establishing a greater breadth and depth to the business. Bert-Jaap will touch on financial performance in a moment. Helped by high crude prices and premiums, we delivered record revenues and operating cash flows notwithstanding Montara, ending the year with balance sheet cash up, including increasing dividends and opening our first share buyback program. Turning to slide four. I'll just spend a minute putting the portfolio in perspective against the broader strategic objectives of building a leading upstream independent in the region. Recognizing that we're targeting an increasingly large pool of opportunities which sit uncomfortably in the hands of their existing owners, we're delivering the key principles of cost management, facility improvements, added reserves, and value creation. We simply want opportunity to be in the right hands. Whether it's stranded assets, under-invested assets, non-strategic assets, or assets immaterial to the majors, we believe we're building a track record across the breadth of activity in a more challenging world of shrinking finance and growing regulatory presence. Let's move to slide five, which summarizes some of the steps we've taken in pursuit of our Net Zero commitment with multiple work streams to support our aim of setting out, by the end of this year, a more detailed roadmap of how we aim to get there. We've made good progress on building a greater understanding of the emissions profiles of our assets. What are the existing and potential mitigation actions, and what is their cost and return? We're now on the final stage of feasibility studies, assessing a short list of reduction options and the detailed implementation plans for each. So far, we're on track to deliver more detail to the Net Zero pathway as promised. We're more convinced than ever that the energy transition requires upstream operators like us, with high standards of governance and transparency, that manage and extend the lives of existing producing fields. This provides essential energy through transition without exploration or major new developments, working with an existing footprint and with a focus on emissions reduction and mitigation, all consistent with the IEA's stated objectives. With that, I think I'll hand over to Bert-Jaap to take you through the financial performance of the business. Bert-Jaap. Thank you, Paul. Good morning or afternoon to all of you. On slide six, o perationally and financially, 2022 has turned out to be a year of two halves for Jadestone, with very strong performance in the first half of the year, while in the second half of the year, the performance was negatively impacted by the Montara shutdown. Especially the charts showing production and operating cash flow shows this difference in financial performance across the both periods. Before talking about the 2022 financials, we note that we incorporated a restatement in the 2021 accounts. The 2021 year-end underlift position in Malaysia, previously valued at market value, was restated by valuing it using production cost. This restatement led to a lower offsetting cost, hence higher 2021 production cost by $5 million, led to lower EBITDAX by the same amount, cash flow after working capital unchanged. On 2022, y ear-on-year, the production expressed in barrels of oil equivalent per day decreased by 8% from 12,545 BOE a day to 11,487 BOE a day, mostly due to the shutdown at Montara, partially offset by a full year of production from the Panmure-operated assets. The decrease in production and the resulting impact on liftings was more than offset by the positive effects from higher oil prices and premiums year-over-year, delivering a record annual revenues and operating cash flow for 2022. Year-on-year, 2022 revenues increased by 24% to $422 million, which includes the contribution of a full year of Panmure and also reflects the $56 million of revenues from the lifting at CWLH in the fourth quarter of 2022. Over the year, 2022 operating cash flow increased by 74% to $158 million, mostly driven by the growth in revenues. The increase in cash balance at the end of the first half of 2022 shows the capacity of the business to generate significant positive cash flow. The year-end cash position, which increased by around $5 million over the full year 2022 to a total of $123 million, was supported by a significant decrease in working capital. I will spend a bit more time on the cash movements later. Over to slide seven. The oil price had a strong positive effect on our 2022 results. In the chart on the left, the realized premium over 2022 of $7.80 per barrel was a record over the last five years and came in at more than twice the realized premium over 2021. This was driven by both the strong Tapis and Stag premium over 2022. In the charts on the right, we show the Brent pricing as well as the average Tapis and Stag premium. It shows that there is some degree of correlation with Brent pricing and the premium realized, which meant that the recent liftings in a lower Brent environment have decreased a bit. In 2022, strength in the Tapis premium was driven by strong cracking margins for gas oil and jet fuel following the border reopening of various Asian countries around the middle of the year 2022. The most recent Panmure listing showed a stabilization of the Tapis premium at around $3-$5 a barrel. The Stag premium was very strong throughout the year as the low sulfur heavy crude remained in high demand. The crude's unique specification makes it very attractive as blending medium to produce shipping fuel. Recent liftings have been in the range of $12.50-$19 per barrel, also in line with recent volatility and Brent prices. Our CWLH crude traded at around $6 per barrel discount to Brent late in 2022 due to weakening Naphtha cracks as a result of decreased demand for end products from China. More recently, CWLH crude has recovered and traded at around Brent pricing. On slide eight. With respect to operating costs, we have created a like-for-like comparison between 2021 and 2022. It shows that despite the inflationary environment, Jadestone has demonstrated a good level of cost control. In 2022, we reported total operating cost of $251 million compared to $212 million in 2021. On CWLH, the 2022 production cost was impacted by a large movement from an underlift to an overlift position of around $34 million following the acquisition with underlying cash calls OpEx of around $4 million. To ensure year-over-year comparability, we've made a small number of adjustments to both 2021 and 2022 reported operating costs. This includes exceptional situations, non-recurring OpEx, Panmure supplementary payments, which vary with oil price, and acquisitions that in any of the both years distorted reported costs. For example, in these charts, CWLH is excluded from 2022, and Panmure is annualized for 2021 to allow comparison. On this basis, the production costs are effectively unchanged year on year at around $170 million. However, we do note that in 2022, we have seen around $13 million lower costs in routine workover activity compared to 2021, which was offset by increases in various other costs with logistics and banker rates as main contributors. This is also the main area where the company saw inflationary pressure in 2022 and early 2023, but which has most recently also seen some cooling. Our largest capital project at Akatara, it has mainly lump sum contracts. On slide nine, we present our usual cash waterfall, setting out the main variations in cash during 2022 and in the separate graph on the right-hand side in the first quarter of 2023. The prolonged Montara shutdown has left its mark on our cash balance, which has decreased significantly since year-end 2022. On this chart, 2022 cash flow generation before working capital investing and shareholder returns was $113 million. CapEx, mostly on the Stag drilling and Lemang project, consumed $83 million, while the net effect of the CWLH acquisition was a consumption of $35 million, mostly representing the $41 million initial payment to the decommissioning fund, offset by the cash received on closing. We returned $25 million cash to shareholders and had a positive working capital effect of $36 million due to the proceeds of liftings received before year-end, and payables, again, mostly related to Stag drilling, carried across the year-end into 2023. As a result, total cash balances increased year-on-year by around $5 million to a total of $123 million at the end of 2022. At the end of the first quarter, 2023, the cash balance was $64 million, which included a drawdown of just below $30 million on our interim facility to fund the Sinphuhorm acquisition. The remaining $20 million of the interim facility is solely available for the next tranche of abandonment funding on CWLH. During the first quarter of 2023, the other main movements in cash were $29 million of net operating cash outflows as liftings and associated revenues in the first quarter were more than offset by operating costs as Montara remained largely offline in the period. $12 million of CapEx, mostly related to the Lemang development, and $13 million related to unwinding of working capital, which was mainly related to payables on the Stag drilling campaign, which finalized late in 2022, which were paid in the first quarter of 2023. On slide 10, we set out our financial framework, which will support our strategy of investing organically as well as acquisition-led growth, primarily through producing assets. With Montara back on stream, we are restoring our cash flow generation with the first 2023 nomination at Montara expected in early June. By the end of 2024, we will have significantly diversified our sources of cash flow with seven producing assets in the mix of gas, fixed and variable pricing, and oil. At that point, Montara is estimated to be around 20% of production. The reserve-based loan, which we expect to close in May, will enable Jadestone to fund its business, including investment in the Akatara development and our infill well campaigns this year. On top of this, the RBL will have the flexibility to integrate producing assets in its borrowing base, enabling the company to fund further acquisitions in an optimal way. We are structuring an accordion, which creates scalability also in support of future acquisitions. We are very encouraged about the opportunity set we have in front of us. Banks are supportive of Jadestone's positioning as responsible operator looking to optimize existing discovered fields, not only on cost production and field life, but also on greenhouse gas emissions. Jadestone's strategy is in line with the IEA guidance of avoiding investment in greenfield assets and focusing on existing production. The RBL has progressed to the point where one bank has obtained credit approval while the other three banks are in the credit approval process. In parallel, the facility and its borrowing base are subject to certain other approvals, including the NOPTA approval of the CWLH title transfer, a decision on which is also expected in May. Hedging of a portion of our production is required for the RBL as this will underpin its debt capacity. We refer to the press release for more details on the RBL status. Over to slide 11. We reiterate the guidance we communicated a couple of weeks ago. We're progressing on our decarbonization's trajectory, and we'll come back with a plan in 2023. The April to December production guidance of 13,500- 17,000 barrels of oil equivalent per day reflects at the lower end of the range, a prudent view of uptime and well performance at Montara, as well as timing of the PM323 Malaysian infill drilling campaign. Our underlying operating costs are expecting to total between $180 million and $210 million, which as usual, excludes several non-routine items. 2023 will mark our second consecutive year of record investments with expected CapEx range of $110 million-$140 million, of which around 70% relates to the Akatara development project and 15% relating to the Panmure drilling. Over to Paul for the operational review. Very good, Bert, yeah. Thanks. Let's move on, if you can, slide 12, which summarizes Jadestone's reserves and resource movements in 2022. This is a good story for the group. 45% growth in 2P reserves during the year, something equivalent to a near six-fold replacement of production. As you can see, the main drivers were the booking of Akatara resources into 2P reserves following the final investment decision, and with a further technical revision to reflect additional volumes committed under the gas sales agreement and some recent liquids upgrades to the recovery from wet gas production. We also added CWLH reserves following the closing of the deal late last year, but hold as much 2C resource in addition following our assessment of the impact that new wells could have on the asset. Overall, the resource base is also growing with significant gas volumes in Vietnam, awaiting development of the Nam Du and U Minh fields, and further upside potential in Vietnam, as well as discovered gas at Montara, which now has the potential export via the nearby Shell-operated Crux field, currently just commencing development. Let's move on to the next slide, where we've provided some detail which reflects on the current status of Montara. Rather than dwelling on the history, which we've discussed on a number of prior calls and in several market updates, I'd just like to give a small context. It's worth recognizing that since we became operator of Montara in 2019, we've been undertaking an ongoing program to revitalize the asset through a systematic process of inspection, remediation, and repair. Progress was impacted by COVID-related manning restrictions, which caused delays to the program and which may have been contributory given we encountered the small hole in tank 2C mere weeks before its scheduled intervention. With that, you know, we've concluded one of the most significant lessons, in our view, is to move away from time-based inspection on the hull, on the vessel, and move to a risk-based approach in the future. While we've now undertaken an extensive eight-month shutdown addressing regulatory actions, carrying out detailed inspections in critical areas and any necessary repairs and maintenance, notwithstanding the major short-term impact on the business, this was something that had to be done, and it had to be done right. We aren't rushing into this, but working systematically to ensure to the best of our ability that there will be no further unplanned events of this nature at Montara. Just to give you an example, in the final stages of the planned shutdown in late January and February, we identified some anomalies in internal coatings in a pressure vessel, as we show on the photos of the reboiler in this slide, as well as finding some minor metallurgy issues on small bore fittings. Generally, these are easily rectified but have delayed the gas system being brought back online. Since we've enjoyed some flush production, this has not been a concern. Since re-restoring production in March, the Montara wells have performed in line with, sorry, beg your pardon. In line with expectations, as we show on the top left of the slide. We can't rush this, but production will ramp up further in the coming days with compression and as additional wells are added and more cargo tanks also to be returned to service. Montara has stress-tested our resilience, I would like to take this moment to recognize the way in which the whole team has responded in these difficult circumstances to work through the issues and bring the asset back on stream. Moving on to slide 14, which provides an update on the tank work on the Montara Venture, providing a whole schematic that shows the phase one program, which is almost complete and which provided sufficient storage and flexibility to allow a restart of production. As we had communicated previously, this subset will be quickly expanded to two further central oil cargo tanks, which moves towards providing capacity for full-sized parcel offloads of around 400,000 barrels. In the meantime, to avoid risk of production interruptions due to storage limitations, an off-take tanker has been chartered for three months to provide storage flexibility. Today, we're just offloading a first parcel of around 150,000 barrels from the FPSO to the tanker. The extent of the activity at Montara, which, you know, with its confined space work, very manual repair and inspection processes and the non-routine tasks, have all been carried out without injury, and it's worth recognizing this also. I'd also conclude the discussion on Montara with a thought that it's only the significantly cash generative nature of the portfolio in general, and Montara in particular, that has ensured we have sufficient cash balances to weather this storm. The strategy we've adopted, acquiring cash flowing assets overlain with capital projects which deliver payback typically in months, will equally see us return to a strong cash position relatively quickly into the future. Now turning to Stag on slide 15, where we highlight in red the two successful wells drilled last year, which utilized donor well slots from old wells with low or no production in a very small and crowded well bay. Typically, all the infill wells have had initial rates at or around 1,000 barrels a day. We hope to continue this trend with some of the new locations highlighted in blue, of which high-graded candidates will be considered for drilling campaign late next year or early the year after. The latest Stag wells, shown on slide 16, are very complex, very long horizontal wells towards the limit of technical feasibility due to complex trajectories, anti-collision, low pressure reservoirs and thin pay. The team are getting better with each well. As a result of challenging the status quo, will likely contribute to several more economic well options emerging. The Stag-50H well targeted unswept oil in the northwest of the field by geosteering across a relatively thin section of reservoir with higher oil saturations, as shown with the hotter orange and yellow shaded areas in the cross-section. We extended the well left to right on the slide by 150 m beyond plan, given the positive indications from the reservoir. Stag-51H was a similarly complex well completed successfully to the east of the field, slightly under budget and building further on our experience at Stag. Slide 17 is a quick recap of our view of the Cossack, Wanaea, Lambert, and Hermes fields, an acquisition from BP, which closed late last year. Strategically, this very high-quality asset with nearly 900 million barrels of oil originally in place and low decline rates, offers significant upside through further infill drilling, unlikely to be carried out by the current partnership. The potential upside we see in the CWLH fields from life extension activities and infill drilling led to a net 6.5 million barrels or circa 40 million barrel gross being booked into contingent resources at year-end. The transaction was completed in November last year for a net receipt of $6 million, given the effective date of January 2020. Half of the required decommissioning security was paid up front and with the remainder to be paid in two installments this year. It is worth just remembering that a stream of cash flow unencumbered by decommissioning costs will generate a very high forward valuation, which translates to a high borrowing capacity, helpful to our current RBL structure. Now moving to Peninsular Malaysia operated assets on slide 18, acquired in August 2021. The team there have been working hard to reduce downtime and decline rates of the fields. With our first infill drilling program on East Belumut to be drilled later this year, if successful, we'll likely see production restored back to the same level at the time of acquisition. As part of our emission strategy touched on earlier, these assets have been identified as candidates for effective investments to mitigate greenhouse gases. The right-hand side of this slide sets out some of the initiatives that are currently underway, where we may see, as a result, a permanent reduction in gas emissions from PM323 and 329. The next slide 19, summarizes the upcoming drilling campaign in more detail. The schematic on the right shows the existing well locations on the East Belumut field and how the proposed infill drilling locations are threaded into areas which are poorly swept. The success case for the infill drilling campaign should add 2,000-2,500 barrels per day of incremental peak gross oil production, with gross drilling costs of around $19 million and a further $10 million for flow line replacement. Drilling should start in August, September and be completed by November. Further drilling campaigns across the Malaysia assets are being assessed with an expectation of more to follow. Now, the non-operated Peninsular Malaysia assets on slide 20, which were acquired as part of the overall SapuraOMV package, I have to say, were not favored at the time due to their non-operated nature with little influence over the state operator. At acquisition, they were a minor part of the deal, producing approximately 1,000 barrels a day net to Jadestone and have been shut in since February last year following the class suspension of the Bunga Kertas FPSO. Following attempts to repair the FPSO in situ, the operator has now decided to withdraw. Recently, we have assumed operatorship in the interest of continuity and efficiency given our existing neighboring operated portfolio. Following an initial valuation, we now believe there may be a very attractive redevelopment opportunity and are currently preparing a submission to the Malaysian upstream regulator for around mid-year time. In the meantime, the previous operator will be responsible for removing the FPSO from its station and towing it to a shipyard in Malaysia later this year. Once there, it will undergo repairs before being handed back to its owner towards the end of the year. The next share to Jadestone of this work is $15 million, although we expect to recoup most of this through existing decommissioning cess funds paying out later this year or in 2024. Now moving to slide 21 and an update on the Akatara project, where by the end of March we were approaching 30% project completion for the EPCI contract for the field facilities. This is just ahead of plan. The civils works at the site are almost complete, after which construction activity will increase with the arrival of equipment for the gas processing plant. In parallel, a number of the existing wells will be re-entered and recompleted into the gas reservoir, sufficient to provide volumes with spare capacity to satisfy the contract quantities under the gas sales agreement. The project remains on track to commission the plant in early 2024, followed by contractual gas sales within the first half. Commercial terms for the LPG and condensate offtake, which are both important and valuable revenue streams in the context of the overall project, will be finished in parallel. We've also shown some images here of the progress in civils works at the main development site to illustrate the acceleration towards key project objectives over the next month. An onshore development with adjacent local communities, there's significant effort being applied to social responsibility in supporting projects for the benefits of local nationals. A very high percentage, over half, of the unskilled and semi-skilled labor is recruited locally, with further commitments to training for the production phase, long-term labor hire, and other benefits such as water supply via water wells at site. Slide 23 provides some commercial context of the project with the gas sales profile from the field shown in red. In addition, there are other profiles associated with analysis from the year-end 2022 competent persons report for the assets by ERCE with low and best cases. These help provide confidence in the assessment of reserves and general subsurface understanding to meet the delivery of contracted volumes. However, additional work completed in-house suggests significant further upside, which will be the subject of more technical work and ultimately lead to additional gas sales as well as longer-term activity in optimizing remaining drilling commitments on the PSC. Now let's move to a slide on Vietnam and Thailand. While we had some success in our efforts to progress commercialization of our significant Vietnam gas resource base through government support for direct end user engagement, progress still does remain slower than we would like. Negotiations have moved forward to the point where there's mutual support to sign a heads of agreement between the two parties, which would allow for an updated field development plan to be prepared and submitted. In the end, there is a declining supply of gas into the Cà Mau Power Station and industrial complex, and there are no practical or economic alternatives to the local gas that Nam Du and U Minh would deliver. There's no prospect of LNG imports to the area in the medium term, no other gas source, and the only physical option would be high-speed diesel. With this dynamic, we continue to believe in the project and the small committed Jadestone team based in Vietnam continues to explore all avenues to move forward the development of this resource which is strategically located to backfill Cà Mau. Moving to Thailand. Following the recent announcement in February of the acquisition of the Sinphuhorm interest onshore Thailand, production has been broadly above plan with nominations for the Nam Phong power plant consistently exceeding the daily contract quantity. This is consistent with our view that the region is short of energy. There's current activity on the asset with a compression expansion project and some drilling. A sidetrack of the PH-19 well is currently being drilled and is expected to complete next month and will be followed by a further well, PH-24. The booster compression project is on track and expected to commence operations in the third quarter next year. As a result, this will be a year of heavy capital for the asset, but will add significantly to extending the asset life. On to slide 24, which I'll use to round off remarks as we look to put the Montara outage behind us and double down on what will positively differentiate us in the sector, doing what we say, delivering growth and value to shareholders. There are a number of catalysts in the short term to look forward to, including progress on Akatara towards first gas next year, closing the RBL, our first drilling campaign in Malaysia on the East Belumut field. A number of M&A opportunities emerging which we'll assess critically to ensure they fit our criteria. An assessment of the former non-operated portfolio in Malaysia. I beg your pardon. Continuing to diversify the business to insulate us from any over-reliance on single events while returning to growth and shareholder value. Finally, before I hand back to the operator for a Q&A, I just wanted to express my thanks to all of the people within Jadestone who worked tirelessly to get us back on track. Despite the periods of significant challenge imposed by the events of the past several months, our colleagues have remained focused and never wavered from doing the right thing. It's been a difficult and frustrating year for our shareholders in particular. Lessons have been learned and implemented, but we do look forward with renewed confidence to the future. With that, I'll hand back to the operator. Thank you very much. Thank you, sir. Ladies and gentlemen, we will now begin the question-and-answer session. Should you have a question, please press star followed by the number one on your touchtone phone. Again, that's star followed by the number one on your touchtone phone. If you would like to withdraw your request, please press star followed by the number two. One moment please for your first question. Your first question comes from the line of Matt Cooper from Peel Hunt. Please go ahead, sir. Your line is live. Good morning, and thank you very much for the presentation. I'm gonna start with three questions on Montara. If you could tell me what your 6,000 barrel a day guidance assumes in terms of post ramp-up rates, and also when that will be achieved. Second question is, given the amount of general maintenance that you've recently been conducting, when is the next scheduled shutdown? Final question on Montara is, are you still planning to increase the amount of bed space on the vessel? Thank you. Thanks, Matt. All somewhat related in a way. The assumption on production, which for the remainder of the year, which of course, you know, does take into account both planned and unplanned maintenance. From a planned maintenance perspective, we do two compressor quick service inspections and blade washes a year. Of course, we've done one now as part of the restart, and there will be one later in the year, late third quarter, early fourth quarter, I imagine, which is in the planning stages. With that, we'll take advantage of, you know, a few days' outage to pick up any other work scope. That's the planned activity at Montara for the remains of the year. That answers, I think, your second question around schedule shutdown. The 6,000, you know, would take into account, you know, that planned outage, a certain proportion of unplanned. If you imagine, you know, on a good day, we can imagine that Montara might be in the 7,000-7,500 barrels range. With shutdowns and so on, it would equate to something around 6,000. That's how I think you should think about it for now. In terms of ramp up, we're working on the final stages of just bringing the compressor online. You know, delays have had nothing to do with the compressor, but a couple of things within the gas system which I've touched on in the presentation. Again, you know, most of it is relatively straightforward physical stuff, not complicated. Weld repair, some bolts that were wrong metallurgy, you know, those sorts of stupid things. Go back to the original vessel conversion. Annoying, but easily fixed. With the gas compressor running, there's an additional four wells that are available with gas lift. I do imagine that we'll be able to bring production up relatively quickly. There is a profile assumed, of course, in our guidance range, which does assume that those gas lift wells will be available within weeks. In terms of bed space, I think one of the key conclusions for us is Montara, you know, we need access to more hands at work sites. We have concluded the first phase of a study to look at the different options for expanding the accommodation, from, you know, small expansion, simple and quick, to something more material, which would require significant modification. In all cases, it needs a safety case to be resubmitted based on whatever plans we come up with. That's part of our thinking. It means it's not something we can do overnight. The three options that we've looked at, are under consideration right now and may be, you know, may be adopted in a phased way, starting with something small and simple and working our way through to something more significant. We have to have more bed space. And that's certainly a key objective. Brilliant. Yeah, that's very comprehensive answers. Appreciate that. Just final question on liquidity. You mentioned in the report an additional non-dilutive funding option is available if RBL close is delayed. If we assume commodity prices stay flat, how much of a delay to RBL close would require you to draw on that? I mean, you know, I mean, essentially it's, you know, it's a reserve plan, Matt. You know, we have a high confidence in progress on the RBL. I'll ask Bert-Jaap if he might just, you know, clarify where exactly we are with the RBL. I mean, you talked about it a little bit already, Bert-Jaap, but maybe just a bit more detail from that, and the audience. I mean, you know, essentially we have a very high confidence there. All of the focus and activity is around that. We wanted, you know, under a worst case scenario, to be able to have a sort of a backstop. We have that arrangement available to us. Bert-Jaap? Yeah, sure. Thanks, Paul. Thanks for the question, Matt. On the RBL, as we've presented as well, one out of the four reputable international banks that we're working with has passed the credit approval stage, which in effect means that the only, let's say gates that we need to pass with this bank is signing the facility agreement. The facility agreement is in near agreed form, which basically means that we just need to do some, you know, last knitting of bits and pieces. It can't be major because otherwise, you know, the credit committee would not be going through an approval. That's one bank. The other three banks are in that same process. Given that one passed it, I think it gives you an impression of where we think the other banks are. Of course, we're not inside those committees and processes itself. We have a pretty high degree of visibility on the other banks as well. When the facility agreement is in agreed form, and the credit committee approvals come through, as expected, in effect, what we then need is the NOPTA decision and of course, the approval of NOPTA for the title transfer of the CWLH asset, which we currently believe it's forthcoming, and we're expecting it in May. This is an important element to the borrowing base and the facility. We're of course working with NOPTA to see how fast we can actually advance the decision making there. We're confident that this is coming forth as well. It's customary CPs, so documentation, reports, you know, the usual customary conditions precedent before we close the facility and can go draw down on it. Yeah, I think all in all, we're very far progressed and we're confident that this will come through in a close in May. Okay, great. That's helpful. Thank you very much, both. Thanks, Matt. Thank you, sir. Your next question comes from the line of Ashley Kelty from Panmure Gordon. Please go ahead, ma'am. Your line's live. Morning, gents. Thanks for this comprehensive presentation. Just had a question around the funding position. If there is any delay to the RBL facility, and there's obviously this backup funding which may or may not be available. Just wondering, in terms of the activity you've got planned, what would be curtailed or rescheduled? Thanks. Hey, Ashley. Thanks. Our Plan B funding is available. You know, our preference is to go with the RBL. It's more comprehensive. It's lower cost. Let's be open about that. That's by far our preference. The alternative is available, you know, we're not contemplating. Yeah. Ashley, I hope we've answered your question. Yeah. Can you hear me, sir? Yeah. The pipe. Yeah, thanks guys. Thank you. Your next question comes from the line of Mr. Mark Wilson from Jefferies. Your line is now live. Go ahead, sir, please. Okay. Hi. Good morning, guys. Thanks, thanks for taking my question. The first point, there's been a number of questions regarding the RBL and the facilities. Can we ask how much the RBL facility size is you're looking to arrange? Is that a fair question? Yes, Mark, bridging up here, of course, that's a fair question. I have to say, of course, you know, it's depending on how credit committees come back. At this point, we can share that we're guessing between $180 million and $210 million. Like I said, it also depends on how credit committees come back. Why is that a variable? Mostly because the capacity of the RBL is also dependent on our hedging program, I refer to that in the presentation as well. The more we hedge, the more borrowing base we can effectively create. There's a bit of a balancing act between what do we need for the RBL and the liquidity that we see that we would require for the various activities that we have in front of us, and the hedging program as, of course, we are, you know, we're what we call oil bulls, if you will. We would wanna be minimizing hedging, and in effect, it's a balancing act between minimizing the hedging for borrowing capacity as well as having sufficient capacity and the ultimate credit committee's approval on sizing. I think that sums it up. On sizing, there's a two-stage approach. I referred to that in the presentation as well, Mark. The It's the original size of the RBL, and some banks have already indicated that they have more capacity than initially put in front of us, which then depends on our implementation of our strategy, essentially, which has all the strands that Paul referred to, and of course, is linked to our plan of acquisitions of producing assets. This is in support of that. Okay. Well, a really quite material facility once in place. Now, you've got operations now across four countries, five, if we include Vietnam as well. And you said, still an extensive set of M&A opportunities ahead. Should we consider that new country entry is also still possible in 2023, or do you think you've covered the main countries that you're focused on? I think it's. You know, when you're in the M&A business, you're responsive to the quality of the opportunity. You don't drive that bus. You respond to it. You know, theoretically, is there, you know, is there a chance of a new country entry? In theory, Mark, but it's highly unlikely. You know, as I think about the things in the market today that we're looking at and likely to come to the market, they would generally fall within the areas where we're already present. Got it. Okay. That's absolutely fine. My last question, just wanna check on the 2023 guidance. In particular, the OpEx, $180 million-$210 million, and CapEx, $110 million-$140 million. Should we think of the OpEx number as being equivalent to the base OpEx numbers you showed on slide right, i.e., of around $170 million the last couple of years? That base level is $180 million-$210 million this year. Is there any of these additional workovers or non-recurring OpEx that we should be putting on top of it, please? Thank you. I think the best way I could think about this to answer your question, if you want to draw that immediate comparison, of course, this year we include a full year of CWLH. This year we include a full year of Sinphuhorm, which wouldn't be comparable to the prior analysis. You know, if you withdraw, you know, in round terms, something like $25 million, I think it's starting to look closer. It's all about what the portfolio includes. Okay? Bert-Jaap, do you want to add? Yeah, I think, Mark, I mean, we didn't wanna sort of confuse the investment community with having another definition, and this is why the analysis that we've done on gross production costs basically ties back on very simple adjustments as far as we're concerned. The non-recurring bit there also ties back to the adjustments that we're making, for example, for adjusted EBITDAX. It's one-on-one linked to those adjustments. For the rest, it's only a few pieces that we adjust for, and it ties back to the accounts. I think it's we really wanted to make sure that we capture call it everything there. On the production guidance number, there are more exclusions because it's more linked to the view that you are used to, with the production per barrel view, which basically excludes some additional items, that we consider as, you know, exceptional as well, including work over, and some transportation, and related. In that sense, it's not one-on-one comparable, and I would use the analysis that we've presented to you as a standalone piece, for the bridge between 2021 and 2022. Thanks for those answers. We can follow up on it. I'll hand it over. Thank you, sir. Just a reminder, should you have a question, please press star followed by the number one on your touchtone phone. Again, that's star one on your touchtone phone. We'll wait for a few seconds for additional questions. There are no further questions at this time. I'd now like to turn the call back over to Mr. Paul Blakeley for closing remarks. Very good. Thank you, operator. Thank you, everybody, for being on the call. I'm not going to say very much more. I think we've had a long discussion about the business. I think we've reached a, you know, a key point in time. We're moving forward, getting back on track, for 2023 and beyond. Growth and value being at the heart of it all. Reliable operations reestablished. And I do hope that, at Montara, particularly, we've turned a key corner, recognizing that one of the strategic objectives that we are well advanced with is to make, you know, Montara, you know, far less material within the business for all the right reasons. We look forward to sharing progress on that, with you all, over the course of the coming year. With that, my thanks to you all. I wish you all a great day. Thank you, sir. Thank you so much, presenters. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines. Have a lovely day.